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Coal Bed Methane Cementing Best Practices

Coal Bed Methane Cementing Best Practices. 10/2/2002. The Basics. Best Practices for “conventional well” cementing still apply Optimize Flow Rates Condition Drilling/Wellbore Fluids Use Spacers and Flushes Centralize the Pipe Pipe Movement Plan to Control Gas Flow. Optimize Flow Rates.

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Coal Bed Methane Cementing Best Practices

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  1. Coal Bed Methane Cementing Best Practices 10/2/2002

  2. The Basics • Best Practices for “conventional well” cementing still apply • Optimize Flow Rates • Condition Drilling/Wellbore Fluids • Use Spacers and Flushes • Centralize the Pipe • Pipe Movement • Plan to Control Gas Flow

  3. Optimize Flow Rates • As with all wells, the key to successful cementing is removal of wellbore fluids and subsequent replacement with cement • Pump Rates can greatly enhance our ability to remove mud, drilling fluids, coal fines and LCM material. • In many parts of the world CBM wells are drilled w/ clear fluids so “mobilization” of the fluids is not a major problem. • In general, faster rates clean the hole better.

  4. Conditioning Drilling/Wellbore Fluids • Clear Drilling/Wellbore Fluids – In general these materials do not build gel strength and are therefore easily removed, the exception is when they are carrying large amounts of fines and LCM. In these scenarios it is best to reduce as much as possible the LCM.

  5. Conditioning Drilling/Wellbore Fluids (con’t) • Drilling Muds – These materials will usually build gel strength. The reduction of gel viscosity is highly recommended to enhance removal. • Break Circulation frequently while running pipe • Reduce Pv, Yp as low as possible while still controlling settling • Maintain Gel Strength as low as possible w/ a flat Gel Strength profile • Reduce Mud filtrate loss – thins the filtercake across permeable zones Horizontal Well applications will require more viscosity to control settling

  6. Spacers and Flushes • Must be matched to the specific Drilling Fluid system to insure compatibility • Highly recommended to separate cement slurries from drilling fluids, preventing contamination • Used to enhance drilling fluid removal efficiency • May incorporate Lost Circulation Materials LCM Materials should be removable – i.e.. acid soluble to reduce permanent formation damage

  7. Centralization • Pipe should be centralized to provide for zonal isolation • Well conditions and Geometry govern the type centralizers used

  8. Pipe Movement during Cementing Operations • Pipe should be either rotated or reciprocated to enhance the cementing performance • In general either movement will be acceptable. However care must be taken when reciprocating if Lost Circulation or gas or water flows have been observed or if the drill string has shown tendencies toward sticking

  9. Gas Control Considerations • Many CBM Projects are drilled under balanced w/ Water, Air, Foam or Mist. Gas Flow Potential can be difficult to measure, but should be accounted for • Short Transition time and Thixotropic cementing systems are recommended • Use of “Gas Generator” additives can also alleviate gas migration

  10. CBM Zonal Isolation Challenges • Formation damage • Isolation within producing zones • Cement fallback • Displacement of washouts across coal • High fracture initiation pressures • Loss of cement returns

  11. Current Wellbore Configurations • CBM Pay behind Pipe – Conventional • May require Multistage cementing • Inflatable packer technology • Foam Cementing Processes*** • Puddle Technique • Top Set • Pay penetrated • All of the above techniques • Pay un-penetrated • Standard cementing techniques

  12. Case History Powder River Basin Rocky Mountain USA Conditions 600-3200’ TD, Vertical, 100OF BHST8 3/4” hole X 7” Casing – Water, Mist or Air drilling fluid, Lost Circulation and cement fallback are common problems, cement to surface req’d Spacers – Fresh water or reactive Cement – 11.2-13.5 ppg Thixotropic, accelerated High Early blends, w/ LCM Foamed Cement systems 7.5-10ppg Pump Rates – 1-2 BPM Other - reciprocation

  13. Case History Raton Basin Rocky Mountain USA Conditions 2000-2200’ TD, Vertical, 120OF BHST7 7/8” hole X 5 1/2” Casing – Water, Mist or Air drilling fluid, Lost Circulation and cement fallback are common problems, cement to surface req’d Spacers – Fresh water w/ Acid soluble LCM Cement – 12-13 ppg Thixotropic, accelerated High Early blends w/ LCM, Gas Migration control Foamed Cement systems 10-12 ppg Pump Rates – 3-4 BPM Other – Centralized, reciprocated

  14. Case History Price, Utah Basin Rocky Mountain USA Conditions 3000-4000’ TD, Vertical, 110OF BHST7 7/8” hole X 5 1/2” Casing – Mist or Air drilling fluid, Then loaded w/ mud to log, Lost Circulation and cement fallback are common problems, cement to surface not req’d. Generally raise cement 500 ft above top coal or back to surface if no loss. Spacers – Fresh water Cement – 12.5-13.6 ppg Thixotropic, accelerated High Early blends w/ LCM Pump Rates – 3-5 BPM Other – Centralized, Generally not reciprocated

  15. Case History Black Warrior Basin Southeast USA Conditions 1700-2200’ TD, Vertical, 130OF BHST7 7/8” hole X 5 1/2” Casing – Water, Mist or Air drilling fluid, Lost Circulation and cement fallback are common problems, cement to surface req’d Spacers – Gelled Fresh water w/ LCM and Poz/cement Scavenger slurries Cement – 12.5-13.5 ppg Thixotropic, accelerated Poz/Cement blends w/ LCM, extenders Foamed Cement systems Pump Rates – 3-4 BPM Other – Centralized, reciprocated

  16. Case History Cotton Plant Basin Southeast USA Conditions 2500-2900’ TD, Vertical, 135F BHST7 7/8” hole X 5 1/2” Casing – Water, Mist or Air drilling fluid, Lost Circulation and cement fallback are common problems, cement to surface req’d Spacers – Reactive and gelled water Cement – 12.5-13.5 ppg Thixotropic, accelerated Poz/Cement blends w/ LCM, extenders Pump Rates – 3-4 BPM Other – Centralized, reciprocated

  17. Case History Moomba Basin Australia Conditions 4000’ TD, Vertical, 140F BHST7 7/8” hole X 5 1/2” Casing – Water-base mud drilling fluid, cement to 2000’, Gas migration is common problem Spacers – Treated KCL water Cement – Foamed Premium Cement 15.8 ppg foamed to 10.5 ppg for a lead and 13.5 ppg across the coal zone12.5-13.5 ppg – Some Multi Stage processes w/extended, thixotropic Poz/cement blends Pump Rates – 3-4 BPM (Fluid) Other – Centralized

  18. Cementing Process Conclusions • Well Conditions Drive Cementing Processes • Use Good Cementing Practices for best Results • Foam Cementing Process are Optimum where available • Thixotropic Slurries are also Preferable • Use care to prevent loss of Materials into potentially productive intervals • Use “removable” products where losses are inevitable

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